U.S. patent application number 17/306793 was filed with the patent office on 2021-08-19 for consolidation and wellbore strength enhancement with caco3 precipitation.
This patent application is currently assigned to Halliburton Energy Services. The applicant listed for this patent is Halliburton Energy Services. Invention is credited to Dale E. JAMISON, Cato R. MCDANIEL, Xiangnan YE.
Application Number | 20210253939 17/306793 |
Document ID | / |
Family ID | 1000005557184 |
Filed Date | 2021-08-19 |
United States Patent
Application |
20210253939 |
Kind Code |
A1 |
YE; Xiangnan ; et
al. |
August 19, 2021 |
CONSOLIDATION AND WELLBORE STRENGTH ENHANCEMENT WITH CaCO3
PRECIPITATION
Abstract
A method of treating a wellbore in a subterranean formation
including introducing a first fluid into a formation, wherein the
first fluid comprises: a first water soluble salt and a carrier;
placing a second fluid into the formation, wherein the second fluid
comprises: a second water soluble salt and a carrier, wherein the
first fluid and second fluid produce a solid precipitate upon
contact; and allowing the solid precipitate to form in-situ in the
formation. An acid may be added to the wellbore after formation of
the precipitate. The method may be also used for stabilizing a
wellbore during drilling, and shutting off and reopening a region
in a formation.
Inventors: |
YE; Xiangnan; (Cypress,
TX) ; MCDANIEL; Cato R.; (Montgomery, TX) ;
JAMISON; Dale E.; (Humble, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Halliburton Energy Services |
Houston |
TX |
US |
|
|
Assignee: |
Halliburton Energy Services
Houston
TX
|
Family ID: |
1000005557184 |
Appl. No.: |
17/306793 |
Filed: |
May 3, 2021 |
Related U.S. Patent Documents
|
|
|
|
|
|
Application
Number |
Filing Date |
Patent Number |
|
|
16338074 |
Mar 29, 2019 |
|
|
|
PCT/US2016/058203 |
Oct 21, 2016 |
|
|
|
17306793 |
|
|
|
|
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 37/00 20130101;
E21B 21/003 20130101; C09K 8/72 20130101; C09K 8/572 20130101; E21B
33/138 20130101 |
International
Class: |
C09K 8/57 20060101
C09K008/57; C09K 8/72 20060101 C09K008/72; E21B 21/00 20060101
E21B021/00; E21B 33/138 20060101 E21B033/138; E21B 37/00 20060101
E21B037/00 |
Claims
1. A method of treating a wellbore in a subterranean formation
comprising: introducing a first fluid into a rock matrix of a
formation, wherein the first fluid comprises a first water soluble
salt and a carrier; introducing a second fluid into the rock matrix
of the formation, wherein the second fluid comprises a second water
soluble salt and a carrier, and wherein the first fluid and second
fluid produce a solid precipitate upon contact; and allowing the
solid precipitate to consolidate to form in-situ in the rock matrix
of the formation and enhance the strength of the rock matrix of the
formation.
2. The method of claim 1, wherein the first water soluble salt is
selected from the group consisting of soluble calcium salts,
soluble magnesium salts, soluble iron (II) salts, soluble iron
(III) salts, and combinations thereof.
3. The method of claim 2, wherein the first water soluble salt is
selected from the group consisting of calcium chlorides, magnesium
chlorides, ferrous chlorides, ferric chlorides, and combinations
thereof.
4. The method of claim 1, wherein the second water soluble salt is
selected from the group consisting of soluble metal carbonates,
soluble metal sulfates, soluble metal phosphates, soluble metal
hydroxides, soluble metal silicates, soluble carbonates, soluble
sulfates, soluble phosphates, soluble hydroxides, soluble
silicates, and combinations thereof.
5. The method of claim 4, wherein the second water soluble salt is
selected from the group consisting of sodium carbonates, sodium
sulfates, sodium phosphates, sodium hydroxides, sodium silicates,
potassium carbonates, potassium sulfates, potassium phosphates,
potassium hydroxides, potassium silicates, ammonium carbonates,
ammonium sulfates, ammonium phosphates, ammonium hydroxides,
ammonium silicates, and combinations thereof.
6. The method of claim 1, wherein the second fluid is introduced
into the rock matrix of the formation before the first fluid is
introduced into the rock matrix of the formation.
7. The method of claim 1, wherein the solid precipitate is selected
from the group consisting of calcium carbonates, calcium sulfates,
calcium phosphates, calcium hydroxides, calcium silicates,
magnesium carbonates, magnesium phosphates, magnesium hydroxides,
magnesium silicates, ferrous carbonates, ferrous phosphates,
ferrous hydroxides, ferrous silicates, ferric carbonates, ferric
phosphates, ferric hydroxides, ferric silicates, and combinations
thereof.
8. The method of claim 1, wherein the solid precipitate is formed
on a surface of a material in the rock matrix of the formation.
9. The method of claim 8, wherein the material is selected from the
group consisting of sandstone, carbonates, shale and combinations
thereof.
10. The method of claim 8, wherein the surface is inner pores.
11. (canceled)
12. The method of claim 1, further comprising deconsolidating the
consolidated solid precipitate within the rock matrix of the
formation by introducing an acid into the rock matrix of the
formation.
13. The method of claim 12, wherein the acid is introduced as at
least one of a pill, a hydrolysable in-situ acid generator, and
combinations thereof.
14. The method of claim 1, wherein the carrier is selected from the
group consisting of fresh water, sea water, brines containing at
least one dissolved organic or inorganic salt, liquids containing
water miscible organic compounds, and combinations thereof.
15. A method for stabilizing a wellbore during drilling in a
subterranean formation, said method comprising: pausing a drilling
operation; introducing a first fluid into a rock matrix of a
formation, wherein the first fluid comprises a first water soluble
salt and a carrier; introducing a second fluid into the rock matrix
of the formation, wherein the second fluid comprises a second water
soluble salt and a carrier, and wherein the first fluid and second
fluid produce a solid precipitate upon contact; allowing the solid
precipitate to consolidate to form in-situ in the rock matrix of
the formation and enhance the strength of the rock matrix of the
formation; and continuing the drilling operation.
16. The method of claim 15, wherein the first water soluble salt is
selected from the group consisting of soluble calcium salts,
soluble magnesium salts, soluble iron (II) salts, soluble iron
(III) salts, and combinations thereof.
17. The method of claim 16, wherein the first water soluble salt is
selected from the group consisting of calcium chlorides, magnesium
chlorides, ferrous chlorides, ferric chlorides, and combinations
thereof.
18. The method of claim 17, wherein the second water soluble salt
is selected from the group consisting of soluble metal carbonates,
soluble metal sulfates, soluble metal phosphates, soluble metal
hydroxides, soluble metal silicates, soluble carbonates, soluble
sulfates, soluble phosphates, soluble hydroxides, soluble
silicates, and combinations thereof.
19. The method of claim 18, wherein the second water soluble salt
is selected from the group consisting of sodium carbonates, sodium
sulfates, sodium phosphates, sodium hydroxides, sodium silicates,
potassium carbonates, potassium sulfates, potassium phosphates,
potassium hydroxides, potassium silicates, ammonium carbonates,
ammonium sulfates, ammonium phosphates, ammonium hydroxides,
ammonium silicates, and combinations thereof.
20. The method of claim 15, wherein the solid precipitate is formed
in a rock matrix selected from the group consisting of sandstone,
carbonates, shale and combinations thereof in the formation.
21. The method of claim 20, wherein the rock matrix is inner
pores.
22. A method of shutting off and reopening a region in a formation,
said method comprising: introducing a first fluid into a region
including a rock matrix in the formation, wherein the first fluid
comprises a first water soluble salt and a carrier; introducing a
second fluid into the region of the formation, wherein the second
fluid comprises a second water soluble salt and a carrier, and
wherein the first fluid and second fluid produce a solid
precipitate upon contact; allowing the solid precipitate to
consolidate to form in-situ in the region of the formation and
enhance the strength of the rock matrix of the formation; and
introducing an acid into the region of the formation.
23. The method of claim 22, wherein the first water soluble salt is
selected from the group consisting of soluble calcium salts,
soluble magnesium salts, soluble iron (II) salts, soluble iron
(III) salts, and combinations thereof.
24. The method of claim 23, wherein the first water soluble is
selected from the group consisting of calcium chlorides, magnesium
chlorides, ferrous chlorides, ferric chlorides, and combinations
thereof.
25. The method of claim 22, wherein the second water soluble salt
is selected from the group consisting of soluble metal carbonates,
soluble metal sulfates, soluble metal phosphates, soluble metal
hydroxides, soluble metal silicates, soluble carbonates, soluble
sulfates, soluble phosphates, soluble hydroxides, soluble
silicates, and combinations thereof.
26. The method of claim 25, wherein the second water soluble salt
is selected from the group consisting of sodium carbonates, sodium
sulfates, sodium phosphates, sodium hydroxides, sodium silicates,
potassium carbonates, potassium sulfates, potassium phosphates,
potassium hydroxides, potassium silicates, ammonium carbonates,
ammonium sulfates, ammonium phosphates, ammonium hydroxides,
ammonium silicates, and combinations thereof.
27. The method of claim 22, wherein the solid precipitate is formed
within inner pores of the rock matrix of the formation.
28. The method of claim 22, wherein the acid is introduced as a
pill, a hydrolysable in-situ acid generator, and combinations
thereof.
29. A wellbore treatment system comprising: an apparatus comprising
a pump and a mixer to: introduce a first fluid into a rock matrix
of a formation, wherein the first fluid comprises a first water
soluble salt and a carrier; introduce a second fluid into the rock
matrix of the formation, wherein the second fluid comprises a
second water soluble salt and a carrier, wherein the first fluid
and second fluid produce a solid precipitate upon contact; allow
the solid precipitate to consolidate to form in-situ in the rock
matrix of the formation and enhance the strength of the rock matrix
of the formation.
30. The method of claim 8, wherein the surface is a combination of
inner pores and external surface of the material.
31. The method of claim 21, wherein the rock matrix is a
combination of inner pores and exterior surfaces of the
material.
32. The method of claim 22, wherein the solid precipitate is formed
within inner pores of the rock matrix and on an exterior surface of
the formation.
33. The method of claim 1, wherein the carrier is an aqueous
carrier, and the first water soluble salt is dissolved in the
carrier.
Description
BACKGROUND
[0001] The present invention generally relates to the use of
precipitates in subterranean operations, and, more specifically, to
soluble salts, and methods of using these soluble salts in
subterranean operations.
[0002] A drilling fluid or mud is a specially designed fluid that
is circulated through a wellbore as the wellbore is being drilled
to facilitate the drilling operation. The various functions of a
drilling fluid include removing drill cuttings from the wellbore,
cooling and lubricating the drill bit, aiding in support of the
drill pipe and drill bit, and providing a hydrostatic head to
maintain integrity of the wellbore walls and to prevent wellbore
blowouts. Specific drilling fluid systems are selected to optimize
a drilling operation in accordance with the characteristics of a
particular geological formation. Because of the diversity of
geological formations encountered in the oil and gas industry,
drilling fluids usually are custom-blended to provide the specific
rheology and other properties required for each situation.
Generally, drilling fluid systems are complex compositions of
liquids (i.e., water, petroleum oil, or synthetic oil or other
synthetic fluid), dissolved inorganic and/or organic additives, and
suspended, finely divided solids of various types.
[0003] Formation damage due to invasion by drilling fluids is a
well-known problem in drilling. Invasion of drilling fluids into
the formation can be caused by the differential pressure of the
hydrostatic column which is generally greater than the formation
pressure, especially in low pressure or depleted zones. Invasion is
also caused or allowed by openings in the rock and the ability of
fluids to move through the rock--the porosity and permeability of
the zone. When drilling depleted sands under an overbalance
condition, which may be several hundreds of pounds per square inch,
mud pressure will penetrate progressively into the formation unless
there is an effective flow barrier present at the wellbore wall.
Horizontal drilling may also drill across highly fractured or
permeable, low pressure or depleted zones, which increases the
probability of the drill pipe getting stuck due to lying on the low
side of the borehole. The exposure of numerous fractures or
openings having low formation pressures has increased the problems
of lost circulation and formation invasion.
[0004] Filtrate control mechanisms have long been used to control
the movement of drilling fluids and filtrate into and through the
formation openings. Such mechanisms traditionally involve adding
particles to the drilling fluid, which are deposited onto the
wellbore wall during circulation of the drilling fluid when
drilling. These particles are commonly bentonite, starch, lignins,
polymers, carbonates, graphitic materials, nutshells, fibrous
materials, barite, drilled solids and various combinations of
these. The particles form a filter cake on the borehole wall which
provides a low permeable barrier. Such traditional solutions,
however, have not been sufficient for eliminating or significantly
reducing lost circulation and formation invasion of drilling fluids
when drilling depleted sands, particularly depleted sands with
overburden pressure amounting to several hundred pounds per square
inch, or across highly fractured or permeable, low pressure or
depleted zones. There continues to be a need for improved methods
for drilling depleted sands.
BRIEF DESCRIPTION OF THE DRAWINGS
[0005] The following figures are included to illustrate certain
aspects of the present invention, and should not be viewed as
exclusive embodiments. The subject matter disclosed is capable of
considerable modification, alteration, and equivalents in form and
function, as will occur to one having ordinary skill in the art and
having the benefit of this disclosure.
[0006] FIG. 1 depicts an embodiment of a system configured for
delivering the treatment fluids of the embodiments described herein
to a downhole location.
[0007] FIGS. 2A-C illustrate SEM images of silica sand particles
before and after the precipitation of CaCO.sub.3.
[0008] FIGS. 3A-B illustrate SEM images of a sandstone core after
the precipitation of CaCO.sub.3.
DETAILED DESCRIPTION
[0009] Embodiments of the invention are directed to precipitating
CaCO.sub.3 in sandstone/shale formations. The methods and fluids
described herein may result in enhanced wellbore strength and
consolidation of sand particles.
[0010] General Measurement Terms and Definitions
[0011] Unless otherwise specified or unless the context otherwise
clearly requires, any ratio or percentage means by volume.
[0012] If there is any difference between U.S. or Imperial units,
U.S. units are intended. Unless otherwise specified, mesh sizes are
in U.S. Standard Mesh.
[0013] The micrometer (.mu.m) may sometimes be referred to herein
as a micron.
[0014] The conversion between pound per gallon (lb/gal or ppg) and
kilogram per cubic meter (kg/m.sup.3) utilized herein is: 1
lb/gal=(1 lb/gal).times.(0.4536 kg/lb).times.(gal/0.003785
m.sup.3)=119.8 kg/m.sup.3.
[0015] As used herein, into a subterranean formation can include
introducing at least into and/or through a wellbore in the
subterranean formation. According to various techniques known in
the art, equipment, tools, or well fluids can be directed from a
wellhead into any desired portion of the wellbore. Additionally, a
well fluid can be directed from a portion of the wellbore into the
rock matrix of a zone.
[0016] Broadly, a zone refers to an interval of rock along a
wellbore that is differentiated from surrounding rocks based on
hydrocarbon content or other features, such as perforations or
other fluid communication with the wellbore, faults, or fractures.
A treatment usually involves introducing a treatment fluid into a
well. As used herein, a treatment fluid is a fluid used in a
treatment. Unless the context otherwise requires, the word
treatment in the term "treatment fluid" does not necessarily imply
any particular treatment or action by the fluid. If a treatment
fluid is to be used in a relatively small volume, for example less
than about 200 barrels, it is sometimes referred to in the art as a
slug or pill. As used herein, a treatment zone refers to an
interval of rock along a wellbore into which a treatment fluid is
directed to flow from the wellbore. Further, as used herein, into a
treatment zone means into and through the wellhead and,
additionally, through the wellbore and into the treatment zone.
[0017] As used herein, into a subterranean formation can include
introducing at least into and/or through a wellbore in the
subterranean formation. According to various techniques known in
the art, equipment, tools, or well fluids can be directed from a
wellhead into any desired portion of the wellbore. Additionally, a
well fluid can be directed from a portion of the wellbore into the
rock matrix of a zone.
[0018] In one or more embodiments, a method of treating a wellbore
in a subterranean formation includes: introducing a first fluid and
a carrier into a formation, wherein the first fluid includes a
first water soluble salt; introducing a second fluid and a carrier
into the formation, wherein the second fluid includes a second
water soluble salt, wherein the first water soluble salt and second
water soluble salt produce a solid precipitate upon contact; and
allowing the solid precipitate to form in-situ in the
formation.
[0019] Carrier
[0020] As used herein, the term "carrier" refers to a water or a
water-miscible but oleaginous fluid-immiscible compound. The
carrier of the present embodiments can generally be from any
source, provided that the fluids do not contain components that
might adversely affect the stability and/or performance of the
wellbore treatment fluids of the present disclosure. Illustrative
aqueous fluids suitable for use in embodiments of this disclosure
include, but are not limited to, fresh water, sea water, brines
containing at least one dissolved organic or inorganic salt,
liquids containing water miscible organic compounds, and
combinations thereof, for example.
[0021] In various embodiments, the brines can include monovalent
brines or divalent brines, for example. Suitable monovalent brines
can include, for example, sodium chloride brines, sodium bromide
brines, potassium chloride brines, potassium bromide brines, and
the combinations thereof. Suitable divalent brines can include, for
example, magnesium chloride brines, calcium chloride brines,
calcium bromide brines, and combinations thereof. In one or more
embodiments, the carrier can include a high density brine. As used
herein, the term `high density brine` refers to a brine that has a
density of about 9.5-10 lbs/gal or greater (1.1 g/cm.sup.3-1.2
g/cm.sup.3 or greater).
[0022] It is contemplated that the carrier contacting the first
fluid and the second fluid may be the same composition.
Alternatively, different compositions may be utilized for each
carrier.
[0023] Water Soluble Salts
[0024] The wellbore treatment fluids of the disclosure include a
first water soluble salt in a carrier and a second water soluble
salt in a carrier. As previously discussed herein, the first water
soluble salt and the second water soluble salt are selected such
that a precipitate is formed upon contact. Thus, it is contemplated
that any combination of water soluble salts capable of producing
such solid precipitate may be utilized. As a non-limiting example,
when calcium chloride contacts sodium carbonate, a precipitate,
calcium carbonate results. Similar results may be observed with
soluble sulfates, phosphates, hydroxides, and silicates.
[0025] The solid precipitate may be formed on one or more surfaces
of the formation. The formation surfaces may be formed of a variety
of materials, including silica, sandstone or shale, for example.
Thus, as used herein, references to "surfaces of the formation"
include interior pores as well as exterior surfaces of the
materials.
[0026] First water soluble salts may include soluble calcium salts,
soluble magnesium salts, soluble iron (II) salts, soluble iron
(III) salts, and combinations thereof. In exemplary embodiments,
the first water salts may include calcium chlorides, magnesium
chlorides, ferrous chlorides, ferric chlorides, and combinations
thereof.
[0027] Second water soluble salts may include soluble metal
carbonates, soluble metal sulfates, soluble metal phosphates,
soluble metal hydroxides, soluble metal silicates, soluble
carbonates, soluble sulfates, soluble phosphates, soluble
hydroxides, soluble silicates, and combinations thereof. More
specifically but not limited thereto, second water soluble salt may
be at least one selected from sodium carbonates, sodium sulfates,
sodium phosphates, sodium hydroxides, sodium silicates, potassium
carbonates, potassium sulfates, potassium phosphates, potassium
hydroxides, potassium silicates, ammonium carbonates, ammonium
sulfates, ammonium phosphates, ammonium hydroxides, ammonium
silicates, and combinations thereof. Table 1 illustrates a variety
of illustrative, non-limiting examples of salts and the resulting
precipitates.
TABLE-US-00001 TABLE 1 First Soluble Salt Second Soluble Salt
Precipitate Calcium chloride Sodium carbonate Calcium carbonate
Calcium chloride Sodium sulfate Calcium sulfate Calcium chloride
Sodium phosphate Calcium phosphate Calcium chloride Sodium
hydroxide Calcium hydroxide Calcium chloride Sodium silicate
Calcium silicate
[0028] Magnesium, iron (II), and iron (III) may replace the calcium
in several of the listings in Table 1. Iron (II) may be used to
make ferrous chloride (FeCl.sub.2). Iron (III) may be used to make
ferric chloride (FeCl.sub.3). Also, potassium may replace the
sodium in the table. It should be noted that iron sulfate and
magnesium sulfate are water soluble.
[0029] In an embodiment, the soluble salts of the invention may be
combined with a carrier in the amount of about 0.1 wt % to about
saturation of the soluble salt in the carrier. In exemplary
embodiments, the soluble salts of the invention may be combined
with a carrier fluid in the amount of about 0.1 wt % to about 25%,
50%, or 75% of saturation of the soluble salt in the carrier.
[0030] The resulting precipitates may result in consolidation of
sands in the formation, enhancement of the wellbore strength or
combinations thereof, for example.
[0031] In an embodiment, the method may further include
deconsolidating the formation by introducing an acid into the
formation upon at least partial precipitation of the first fluid
and second fluid. The deconsolidation process occurs when the solid
precipitate is dissolved with an acid. Such deconsolidation
processes may be useful when a zone or region that has been
previously closed after using the precipitation methods discussed
above needs to be reopened. The acid may be added as at least one
of a pill, a hydrolysable in-situ acid generator, or combinations
thereof. Acid pills may include HCl acid, formic acid, or any acid
that dissolves the precipitate. The precipitates need to be
dissolvable in the acids for deconsolidation to occur. Not all
precipitates may be re-dissolved, including for example, phosphates
such as iron phosphate and calcium phosphate.
[0032] The treatment methods and fluids used for deconsolidation
may also include hydrolysable in-situ acid generating compounds.
After combining these compounds with an aqueous solution (carrier),
an acid is formed. The acid may form instantaneously, or the
formation of the acid may take hours or days, for example. In some
embodiments, the in-situ acid generating compounds are esters,
aliphatic polyesters, ortho esters, which may also be known as
ortho ethers, poly (ortho esters), which may also be known as
poly(ortho ethers), poly(lactides), poly(glycolides),
poly(c-caprolactones), poly(hydroxybutyrates), poly(anhydrides),
copolymers thereof, derivatives thereof or combinations thereof.
The term "copolymer" as used herein is not limited to the
combination of two polymers, but includes any combination of
polymers, e.g., terpolymers. In several embodiments, the
hydrolysable acid ester includes at least one member selected homo-
and copolymers of lactic and glycolic acid, homo- and copolymers of
vinyl methylsulphonate and vinyl methylphosphonate and
dimethylphosphonate; and any combination thereof. Other suitable
acid-generating compounds include: esters including, but not
limited to, ethylene glycol monoformate, ethylene glycol diformate,
diethylene glycol diformate, glyceryl monoformate, glyceryl
diformate, glyceryl triformate, triethylene glycol diformate and
formate esters of pentaerythritol. In various embodiments, an
amount of the hydrolysable in-situ acid generating compound present
in the deconsolidation treatment fluids ranges from about 1 wt. %
to about 30 wt. %, alternatively, about 5 wt. % to about 20 wt. %
alternatively about 10 wt. % to about 15 wt. % based on the total
weight of carrier used in the deconsolidation treatment fluid.
[0033] Other Additives
[0034] In addition to the foregoing materials, it can also be
desirable, in some embodiments, for other components to be present
in the treatment methods and fluids. Such additional components can
include, without limitation, surfactants, gelling agents, fluid
loss control agents, proppants, corrosion inhibitors, rheology
control modifiers or thinners, viscosity enhancers, temporary
viscosifying agents, filtration control additives, high
temperature/high pressure control additives, emulsification
additives, surfactants, acids, alkalinity agents, pH buffers,
fluorides, gases, nitrogen, carbon dioxide, surface modifying
agents, tackifying agents, foamers, scale inhibitors, catalysts,
clay control agents, biocides, bactericides, friction reducers,
antifoam agents, bridging agents, dispersants, flocculants,
H.sub.2S scavengers, CO.sub.2 scavengers, oxygen scavengers,
friction reducers, breakers, relative permeability modifiers,
resins, wetting agents, coating enhancement agents, filter cake
removal agents, surfactants, defoamers, shale stabilizers, oils, or
combinations thereof. One or more of these additives (e.g.,
bridging agents) may comprise degradable materials that are capable
of undergoing irreversible degradation downhole. A person skilled
in the art, with the benefit of this disclosure, will recognize the
types of additives that may be included in the fluids of the
present disclosure for a particular application, without undue
experimentation.
[0035] Methods of Use
[0036] The methods of the present invention may be employed in any
subterranean treatment where a viscoelastic treatment fluid may be
used. Suitable subterranean treatments may include, but are not
limited to, drilling, fracturing treatments, sand control
treatments (e.g., gravel packing), and other suitable treatments
where a treatment fluid of the present invention may be
suitable.
[0037] In addition to the fracturing fluids used in fracturing
treatments, other fluids used in servicing a wellbore may also be
lost to the subterranean formation while circulating the fracturing
fluids in the wellbore. In particular, the other fluids may enter
the subterranean formation via lost circulation zones for example,
depleted zones, zones of relatively low pressure, zones having
naturally occurring fractures, weak zones having fracture gradients
exceeded by the hydrostatic pressure of the drilling fluid, and so
forth.
[0038] A method of treating in a subterranean formation may include
introducing a first fluid into a formation followed by a second
fluid. The first fluid may be created by combining a first water
soluble salt and a carrier. The second fluid may be created by
combining a second water soluble salt and a carrier. The method may
also include introducing the second fluid into the formation
followed by introducing the first fluid into the formation.
[0039] The methods and fluids of the present application may also
be used in drilling applications. The fluids may assist in carrying
drill cuttings to the surface and stabilizing the wellbore. A
method of stabilizing a wellbore during drilling of said wellbore
through sandstone, carbonates, shale, and combinations thereof in a
subterranean formation may include pausing drilling operations,
introducing a first fluid into a formation followed by a second
fluid, allowing a solid precipitate to form in-situ in the
formation, and continuing the drilling operation. The method may
also include introducing the second stream into the formation
followed by introducing the first stream into the formation.
[0040] A method of shutting off and reopening a region in a
formation including sandstone, carbonates, shale, and combinations
thereof may include introducing a first fluid into a region of a
formation followed by a second fluid, allowing a solid precipitate
to form in-situ in the region of the formation, and introducing an
acid into the region of the formation. The acid may be introduced
as a pill, a hydrolysable in-situ acid generator, and combinations
thereof.
[0041] The treatment fluids of the present invention may be
prepared by any method suitable for a given application. For
example, certain components of the treatment fluid may be provided
in a pre-blended powder or a dispersion of powder in a nonaqueous
liquid, which may be combined with the carrier at a subsequent
time. After the preblended liquids and the aqueous base fluid have
been combined other suitable additives may be added prior to
introduction into the wellbore. Those of ordinary skill in the art,
with the benefit of this disclosure will be able to determine other
suitable methods for the preparation of the treatments fluids of
the present invention.
[0042] In still another exemplary embodiment, the separate
introduction of at least two of the treatment fluid components may
be achieved by introducing the components within a single flowpath,
but being separated by a spacer. Such a spacer may comprise a
highly viscous fluid which substantially or entirely prevents the
intermingling of the treatment fluid components while being pumped
into a wellbore. Such spacers and methods of using the same are
generally known to those of ordinary skill in the art.
[0043] In various embodiments, systems configured for delivering
the treatment fluids described herein to a downhole location are
described. In various embodiments, the systems can comprise a pump
fluidly coupled to a tubular, the tubular containing the treatment
fluids disclosed herein.
[0044] A wellbore treatment system may include an apparatus
including a pump and a mixer to introduce a first fluid into a
formation followed by a second fluid, and allow a solid precipitate
to form in-situ in the formation.
[0045] The pump may be a high pressure pump in some embodiments. As
used herein, the term "high pressure pump" will refer to a pump
that is capable of delivering a fluid downhole at a pressure of
about 1000 psi or greater. A high pressure pump may be used when it
is desired to introduce the treatment fluid to a subterranean
formation at or above a fracture gradient of the subterranean
formation, but it may also be used in cases where fracturing is not
desired. In some embodiments, the high pressure pump may be capable
of fluidly conveying particulate matter, such as proppant
particulates, into the subterranean formation. Suitable high
pressure pumps will be known to one having ordinary skill in the
art and may include, but are not limited to, floating piston pumps
and positive displacement pumps.
[0046] In other embodiments, the pump may be a low pressure pump.
As used herein, the term "low pressure pump" will refer to a pump
that operates at a pressure of about 1000 psi or less. In some
embodiments, a low pressure pump may be fluidly coupled to a high
pressure pump that is fluidly coupled to the tubular. That is, in
such embodiments, the low pressure pump may be configured to convey
the treatment fluid to the high pressure pump. In such embodiments,
the low pressure pump may "step up" the pressure of the treatment
fluid before it reaches the high pressure pump.
[0047] In embodiments, the disclosed wellbore treatment fluid may
be prepared at a well site or at an offsite location. Once
prepared, a treatment fluid of the present disclosure may be placed
in a tank, bin, boat, barge or other container for storage and/or
transport to the site where it is to be used. In other embodiments,
a treatment fluid of the present disclosure may be prepared
on-site, for example, using continuous mixing, on-the-fly mixing,
or real-time mixing methods. In certain embodiments, these methods
of mixing may include methods of combining two or more components
wherein a flowing stream of one element is continuously introduced
into flowing stream of another component so that the streams are
combined and mixed while continuing to flow as a single stream as
part of the on-going treatment. The system depicted in FIG. 1
(described further below) may be one embodiment of a system and
equipment used to accomplish on-the-fly or real-time mixing.
[0048] In some embodiments, the systems described herein can
further comprise a mixing tank that is upstream of the pump and in
which the treatment fluid is formulated. In various embodiments,
the pump (e.g., a low pressure pump, a high pressure pump, or a
combination thereof) may convey the treatment fluid from the mixing
tank or other source of the treatment fluid to the tubular. In
other embodiments, however, the treatment fluid can be formulated
offsite and transported to a worksite, in which case the treatment
fluid may be introduced to the tubular via the pump directly from
its shipping container (e.g., a truck, a railcar, a barge, or the
like) or from a transport pipeline. In either case, the treatment
fluid may be drawn into the pump, elevated to an appropriate
pressure, and then introduced into the tubular for delivery
downhole.
[0049] FIG. 1 shows an illustrative schematic of a system that can
deliver treatment fluids of the embodiments disclosed herein to a
downhole location, according to one or more embodiments. It should
be noted that while FIG. 1 generally depicts a land-based system,
it is to be recognized that like systems may be operated in subsea
locations as well. As depicted in FIG. 1, system 1 may include
mixing tank 10, in which a treatment fluid of the embodiments
disclosed herein may be formulated. The treatment fluid may be
conveyed via line 12 to wellhead 14, where the treatment fluid
enters tubular 16, tubular 16 extending from wellhead 14 into
subterranean formation 18. Upon being ejected from tubular 16, the
treatment fluid may subsequently penetrate into subterranean
formation 18. Pump 20 may be configured to raise the pressure of
the treatment fluid to a desired degree before its introduction
into tubular 16. It is to be recognized that system 1 is merely
exemplary in nature and various additional components may be
present that have not necessarily been depicted in FIG. 1 in the
interest of clarity. Non-limiting additional components that may be
present include, but are not limited to, supply hoppers, valves,
condensers, adapters, joints, gauges, sensors, compressors,
pressure controllers, pressure sensors, flow rate controllers, flow
rate sensors, temperature sensors, and the like.
[0050] Although not depicted in FIG. 1, the treatment fluid may, in
some embodiments, flow back to wellhead 14 and exit subterranean
formation 18. In some embodiments, the treatment fluid that has
flowed back to wellhead 14 may subsequently be recovered and
recirculated to subterranean formation 18.
[0051] It is also to be recognized that the disclosed treatment
fluids may also directly or indirectly affect the various downhole
equipment and tools that may come into contact with the treatment
fluids during operation. Such equipment and tools may include, but
are not limited to, wellbore casing, wellbore liner, completion
string, insert strings, drill string, coiled tubing, slickline,
wireline, drill pipe, drill collars, mud motors, downhole motors
and/or pumps, surface-mounted motors and/or pumps, centralizers,
turbolizers, scratchers, floats (e.g., shoes, collars, valves,
etc.), logging tools and related telemetry equipment, actuators
(e.g., electromechanical devices, hydromechanical devices, etc.),
sliding sleeves, production sleeves, plugs, screens, filters, flow
control devices (e.g., inflow control devices, autonomous inflow
control devices, outflow control devices, etc.), couplings (e.g.,
electro-hydraulic wet connect, dry connect, inductive coupler,
etc.), control lines (e.g., electrical, fiber optic, hydraulic,
etc.), surveillance lines, drill bits and reamers, sensors or
distributed sensors, downhole heat exchangers, valves and
corresponding actuation devices, tool seals, packers, cement plugs,
bridge plugs, and other wellbore isolation devices, or components,
and the like. Any of these components may be included in the
systems generally described above and depicted in FIG. 1.
[0052] The invention having been generally described, the following
examples are given as particular embodiments of the invention and
to demonstrate the practice and advantages hereof. It is understood
that the examples are given by way of illustration and are not
intended to limit the specification or the claims to follow in any
manner.
EXAMPLES
[0053] Consolidation and Enhancement
[0054] Compositions: [0055] 1 molar solution of sodium carbonate
and calcium chloride
[0056] Experimental Procedure:
[0057] 1. Sodium carbonate and calcium carbonate were combined in
the presence of loose sand.
[0058] As seen in FIGS. 2A and B, the loose sand before the
precipitate is formed (FIG. 2A) is consolidated after the
precipitation (FIG. 2B). FIG. 2C shows the consolidation of the
loose sand after the sample has been dried. The results illustrate
that the calcium carbonate precipitate successfully consolidated
loose sand.
[0059] 2. A sandstone core sample was submerged in a sodium
carbonate solution and then transferred to a calcium carbonate
solution. The sample was kept in the solution in an oven a
150.degree. F. (66.degree. C.) overnight.
[0060] Results
[0061] Precipitation occurred instantly, in less than one second,
upon contact with the calcium carbonate solution, on the outside of
the core surface as seen in FIG. 3A. The process of CaCO.sub.3
crystal growth after the initial precipitation (nucleation), may
take longer depending on the reaction conditions. Precipitation was
also observed inside the core sample as illustrated in FIG. 2B.
Because porosity of the core sample significantly decreased after
treatment, one of skill in the art may expect the enhancement of
the core strength.
[0062] Embodiments disclosed herein include:
[0063] A: A method of treating a wellbore in a subterranean
formation comprising introducing a first fluid into a formation,
wherein the first fluid comprises a first water soluble salt and a
carrier; introducing a second fluid into the formation, wherein the
second fluid comprises a second water soluble salt and a carrier,
and wherein the first fluid and second fluid produce a solid
precipitate upon contact; and allowing the solid precipitate to
form in-situ in the formation.
[0064] B: A method for stabilizing a wellbore during drilling of
said wellbore through a material selected from sandstone,
carbonates, shale, and combinations thereof in a subterranean
formation comprising a material selected from sandstone,
carbonates, shale, and combinations thereof, said method comprising
pausing a drilling operation; introducing a first fluid into a
formation, wherein the first fluid comprises a first water soluble
salt and a carrier; introducing a second fluid into the formation,
wherein the second fluid comprises a second water soluble salt and
a carrier, and wherein the first fluid and second fluid produce a
solid precipitate upon contact; allowing the solid precipitate to
form in-situ in the formation; and continuing the drilling
operation.
[0065] C: A method of shutting off and reopening a region in a
formation comprising a material selected from sandstone,
carbonates, shale, and combinations thereof, said method comprising
introducing a first fluid into a region in the formation, wherein
the first fluid comprises a first water soluble salt and a carrier;
introducing a second fluid into the region of the formation,
wherein the second fluid comprises a second water soluble salt and
a carrier, and wherein the first fluid and second fluid produce a
solid precipitate upon contact; allowing the solid precipitate to
form in-situ in the region of the formation; and introducing an
acid into the region of the formation.
[0066] D: A well treatment system comprising: a well treatment
apparatus, including a pump and a mixer to introduce a first fluid
into a formation, wherein the first fluid comprises a first water
soluble salt and a carrier; introduce a second fluid into the
formation, wherein the second fluid comprises a second water
soluble salt and a carrier, and wherein the first fluid and second
fluid produce a solid precipitate upon contact; and allow the solid
precipitate to form in-situ in the formation.
[0067] Each of embodiments A, B, C and D may have one or more of
the following additional elements in any combination: Element 1:
wherein the first water soluble salt is selected from soluble
calcium salts, soluble magnesium salts, soluble iron (II) salts,
soluble iron (III) salts, and combinations thereof. Element 2:
wherein the first water soluble salt is selected from calcium
chlorides, magnesium chlorides, ferrous chlorides, ferric
chlorides, and combinations thereof. Element 3: wherein the second
water soluble salt is selected from soluble metal carbonates,
soluble metal sulfates, soluble metal phosphates, soluble metal
hydroxides, soluble metal silicates, soluble carbonates, soluble
sulfates, soluble phosphates, soluble hydroxides, soluble
silicates, and combinations thereof. Element 4: wherein the second
water soluble salt is selected from sodium carbonates, sodium
sulfates, sodium phosphates, sodium hydroxides, sodium silicates,
potassium carbonates, potassium sulfates, potassium phosphates,
potassium hydroxides, potassium silicates, ammonium carbonates,
ammonium sulfates, ammonium phosphates, ammonium hydroxides,
ammonium silicates, and combinations thereof. Element 5: wherein
the second fluid is introduced into the formation before the first
fluid is introduced into the formation. Element 6: wherein the
solid precipitate is selected from calcium carbonates, calcium
sulfates, calcium phosphates, calcium hydroxides, calcium
silicates, magnesium carbonates, magnesium phosphates, magnesium
hydroxides, magnesium silicates, ferrous carbonates, ferrous
phosphates, ferrous hydroxides, ferrous silicates, ferric
carbonates, ferric phosphates, ferric hydroxides, ferric silicates,
and combinations thereof. Element 7: wherein the solid precipitate
is formed on a surface of a material in the formation. Element 8:
wherein the material is selected from sandstone, carbonates, shale
and combinations thereof. Element 9: wherein the surface is
selected from inner pores, exterior surfaces of the material, and
combinations thereof. Element 10: wherein the solid precipitate
enhances the wellbore strength. Element 11: further comprising
deconsolidating the formation by introducing an acid into the
formation upon formation of the solid precipitate. Element 12:
wherein the acid is introduced as at least one of a pill, a
hydrolysable in-situ acid generator, and combinations thereof.
Element 13: wherein the carrier is selected from fresh water, sea
water, brines containing at least one dissolved organic or
inorganic salt, liquids containing water miscible organic
compounds, and combinations thereof.
[0068] The particular embodiments disclosed above are illustrative
only, as the present disclosure may be modified and practiced in
different but equivalent manners apparent to those skilled in the
art having the benefit of the teachings herein. Furthermore, no
limitations are intended to the details of construction or design
herein shown, other than as described in the claims below. It is
therefore evident that the particular illustrative embodiments
disclosed above may be altered or modified and all such variations
are considered within the scope and spirit of the present
disclosure. While compositions and methods are described in terms
of "comprising," "containing," or "including" various components or
steps, the compositions and methods can also "consist essentially
of" or "consist of" the various components and steps. All numbers
and ranges disclosed above may vary by some amount. Whenever a
numerical range with a lower limit and an upper limit is disclosed,
any number and any included range falling within the range is
specifically disclosed. In particular, every range of values (of
the form, "from about a to about b," or, equivalently, "from
approximately a to b," or, equivalently, "from approximately a-b")
disclosed herein is to be understood to set forth every number and
range encompassed within the broader range of values. Also, the
terms in the claims have their plain, ordinary meaning unless
otherwise explicitly and clearly defined by the patentee. Moreover,
the indefinite articles "a" or "an", as used in the claims, are
defined herein to mean one or more than one of the element that it
introduces. If there is any conflict in the usages of a word or
term in this specification and one or more patent or other
documents, the definitions that are consistent with this
specification should be adopted.
[0069] Numerous other modifications, equivalents, and alternatives,
will become apparent to those skilled in the art once the above
disclosure is fully appreciated. It is intended that the following
claims be interpreted to embrace all such modifications,
equivalents, and alternatives where applicable.
* * * * *